Tracer methods are frequently employed to observe the flow of fluids in subterranean geologic formations and to measure fluid content and other properties of these formations. Previous practice in the use of tracers have generally involved either single well or interwell tests. In the single well method, the tracer is injected into a well and then recovered by backflow into the same well. In the interwell method, the tracer is injected into the inflow stream of an injection well and is driven to a producing well (or wells) where it is captured. Tracer methods such as these are frequently used in oil field reservoirs to evaluate the connectivity of well pairs, to observe directional permeability, to determine fluid saturations, and to assess the flooding efficiency of oil recovery processes.
Typically, an oil-productive formation is a stratum of rock containing small interconnected pore spaces which are saturated with oil, water, and/or gas. As fluids are produced from such a formation, the oil can adhere to the rock surfaces or be trapped in the pore spaces. In either case the water becomes the more mobile phase. Hydrocarbons produced into wellbores by primary drive mechanisms are often replaced with indigenous brine which flows from expanding aquifers down-dip of producing well boreholes toward the producing wells. Hydrocarbons can also be recovered by secondary drive mechanisms such as water flooding. In a water flood, injected water displaces the reservoir fluids into the producing wellbores. Regardless of the source of the water, much of the pore space is eventually filled with a continuous brine phase. A reservoir in this condition is referred to as a watered-out reservoir. Additional oil can be recovered from such a reservoir, but, being almost immobile, it is produced with large volumes of water. Ultimately the production of oil from high water cut wells becomes uneconomical and continued economical production of oil may then require application of another oil recovery method. In planning these processes, knowledge of the amount of oil remaining in the formation is a critical factor that is needed to evaluate economics of the various secondary and tertiary oil recovery methods.
Various methods to determine residual oil saturation in such a formation are known, but each has drawbacks and limitations. One frequently used way to determine residual oil saturation is to drill a rock sample core from the formation and determine the oil content of the rock sample. This method is susceptible to faults of the sampling technique because the necessarily small sample that can be taken may not be representative of the formation as a whole. Also, there is a genuine possibility that the coring process itself may change the fluid saturation by flushing the recovered core. Moreover, coring can only be employed in newly drilled wells or by expensive sidetrack operations. Since the vast majority of wells have casing set through the oil-bearing formation when the well is initially completed, core samples are seldom recovered from existing wells.
Another approach for obtaining reservoir fluid saturations is by logging techniques. These techniques investigate a somewhat larger sample of the formation rock, but still are limited to the region relatively close to the wellbore. Fluid invasion into this region during drilling and completion prior to logging complicates quantitative measurement of fluid saturation. In addition, rapid changes in formation properties with depth often affect the log interpretation. Since logging methods measure the rock fluid system as an entity, it is often difficult to differentiate between mineralogical and fluid properties.
Material balance calculations based on production history are still another way to estimate remaining oil. Estimates of fluid saturation acquired by this method are subject to even more variability than coring or logging. This technique requires knowledge, by other methods, of the initial fluid saturation of the formation and the sweep efficiency of the encroaching fluids.
To overcome some of these shortcomings, tracer tests have been developed that utilize principles of chromatography to determine residual oil saturation from the separation of water-soluble-only tracers and oil-water partitioning tracers during their passage through the reservoir formation. U.S. Pat. No. 3,590,923 discloses such a process. In this process, an aqueous solution comprising the water-soluble tracer, and the partitioning tracer is injected in an injection well, and then is driven to a production well by injection of brine. The amounts of fluids produced before each of the tracers is detected, together with the partition coefficient of the partly oil-soluble tracer, are used to indicate the formation residual oil saturation. Driving the tracers from the injection wellbore initially forces the tracers out radially, so that, in reasonable times, the producing well will capture only a small fraction of the injected tracers. Large amounts of tracers must therefore be injected. Further, if the field is not already being subjected to a water flood, large volumes of brine must be provided to inject and drive the tracers. When the formation is not being subjected to a water flood, the cost of installing water injection facilities and of injecting brine is typically prohibitive. When a watered-out formation is not being subjected to a flood, methods are available which utilize chromatographic separation of tracers, first by injection of multiple tracer precursers into a well, reaction of at least one precurser into a partitioning tracer or a water soluble tracer, and then by backflow production from the same well. These methods are referred to as single well tracer tests. Such methods are disclosed in, for example, U.S. Pat. Nos. 3,623,842, 3,751,226, 3,856,468, 4,617,994, 4,646,832, 4,722,394, and 4,782,898. These methods have drawbacks which include: (1) difficulty of controlling the reaction when an injected precursor is used to generate a tracer within the formation; (2) differences in flow profiles between the injection and production periods; (3) crossflow of fluids between vertical layers; (4) the need to dedicate a well to such a test for an extended time period; and (5) sampling only a limited portion of the formation.
It is therefore an object of this invention to provide a more efficient method of capturing tracer at a producing well in the measurement of the residual oil saturation of an oil-producing formation. It is a further object to provide a method to determine the residual oil saturation over a significant portion of the formation, wherein water flooding is not needed, and wherein normal production is maintained throughout the test.